Method for Viscous Hydrocarbon Production Incorporating Steam and Solvent Cycling

ABSTRACT

A method for producing hydrocarbons from a reservoir containing the hydrocarbon comprises a steam assisted gravity drainage (SAGD) incorporating cyclic steam, heavy (e.g. greater than C4) solvent and light (e.g. C2 to C4) solvent injection. The method involves a series of steps wherein the injection of the respective streams is varied. The method provides a significant improvement in hydrocarbon extraction efficiency as compared to a SAGD process alone and mitigates many of the drawbacks associated with typical SAGD operations.

CROSS REFERENCE TO RELATED APPLICATIONS

The present application claims priority from U.S. application No.61/173,911, filed on Apr. 29, 2009, the entire contents of which areincorporated herein by reference.

FIELD OF THE INVENTION

The present invention relates to the production of hydrocarbons, inparticular viscous hydrocarbons, from petroleum deposits. Morespecifically, the invention relates to an improved method for producinghydrocarbons from formations, such as “oil sands”, incorporating cyclicapplications of steam and solvent.

BACKGROUND OF THE INVENTION

Oil sand deposits are found predominantly in the Middle East, Venezuela,and Western Canada. The Canadian bitumen deposits, being the largest inthe world, are estimated to contain between 1.6 and 2.5 trillion barrelsof oil, so the potential economic benefit of this invention carriessignificance within this resource class. The term “oil sands” refers tolarge subterranean land forms composed of reservoir rock, water andheavy oil and/or bitumen. Bitumen is a heavy, black oil which, due toits high viscosity, cannot readily be pumped from the ground like othercrude oils. Therefore, alternate processing techniques must be used toextract the bitumen deposits from the oil sands, which remain a subjectof active development in the field of practice. The basic principle ofknown extraction processes is to lower the viscosity of the bitumen byapplying heat, injecting chemical solvents, or a combination thereof, toa deposit layer, thereby promoting flow of the material throughout thetreated reservoir area, in order to allow for recovery of bitumen fromthat layer.

A variety of known extraction processes are commercially used to recoverbitumen from oil deposits. Steam-Assisted Gravity Drainage, commonlyreferred to as SAGD, is one known method. A SAGD process is described,for example, in Canadian patent number 1,304,287. In a SAGD process,steam is injected into a target reservoir through a horizontal injectionwell to heat heavy crude oil within a reservoir. The range oftemperatures, and corresponding viscosities, required to achieve aneconomic flow rate is dependent on the permeability of the reservoir inquestion. SAGD, as with most recovery strategies, is focused onincreasing bitumen temperature within a limited region around a steaminjection well. The reduced-viscosity oil is then allowed to flow bygravity drainage to an underlying point of the reservoir and to becollected by a horizontal production well. The heavy oil/bitumen is thenbrought to the surface for further processing. Various pumping equipmentand/or systems may be used in association with the production well.Although effective, stand alone SAGD processes have several associatedinefficiencies. Firstly, the process is very energy intensive, requiringa great amount of energy for heating the volumes of water to generatethe steam used for the heat transfer process. In addition, the amount ofsteam required is usually dictated by the need to maintain a certainpressure in the reservoir; this usually translates into a highertemperature than is optimally needed to mobilize the bitumen. Further,upon releasing its heat to the formation, the injected steam condensesinto water, which mixes with the mobilized bitumen and often leads toadditional inefficiencies. For example, the water must be recycledthrough the boilers, requiring costly de-oiling and softening processes.In addition, the original or initial separation of the bitumen and waterrequires further processing and costs associated with such procedures.Also, as common with other known active heating methods, the energyinput to the deposit is often transferred to neighbouring geologicalstructures and lost by way of conduction. Thus, the process becomesconsiderably energy intensive in order to achieve sufficient heating ofthe target formation. As a result, SAGD processes are typically onlycommercially viable for reservoirs having a minimum volume andconcentration of hydrocarbons.

Dilution is another technique that has been used for the extraction ofbitumen from oil sand or heavy oil deposits. Such methods, oftenreferred to as vapour extraction methods, or VAPEX, involve a dilutionprocess wherein solvents, such as light alkanes or other relativelylight hydrocarbons, are injected into a deposit to dilute the heavy oilor bitumen. This technique also reduces the viscosity of the heavyhydrocarbon component, thereby facilitating recovery of thebitumen-solvent mixture that is mobilized throughout the reservoir. Theinjected solvent is produced along with bitumen material and somesolvent can be recovered by further processing. Although VAPEX methodsavoid the costs associated with SAGD methods, the production rate ofsolvent based methods has been found to be less than steam basedprocesses. A VAPEX method also requires processing facilities for theextraction of the injected solvent. Finally, VAPEX methods tend toaccumulate material quantities of liquid solvent within the depletedpart of the reservoir. Such solvents cannot be recovered until the endof the process thereby representing an economically significant cost forthe solvent inventory.

A combination of SAGD and VAPEX methods has also been proposed in orderto combine the benefits of both while mitigating the drawbacksassociated therewith. Known as a solvent aided, or solvent assistedprocess, or SAP, this method involves the injection of both steam and alow molecular weight hydrocarbon into the formation. Gupta et al. (J.Can. Pet. Tech., 2007, 46(9), pp. 57-61) teach a SAP method, whichcomprises a SAGD process wherein a solvent is simultaneously injectedinto the formation with the steam. As indicated in this reference, a SAPprocess has been found to improve the economics of SAGD methods. Thisreference also teaches that, due to such improved economics, it ispossible to widen the spacing of wells used in a SAP process, therebyreducing capital costs as compared to SAGD alone. Gupta et al. alsoteach that using solvents with successively decreasing molecular weightsallows for increased recovery rates of the heavier solvents at the costof the lighter ones. This is beneficial as the heavier solvents aregenerally more expensive.

Other examples of SAP types of methods are described in U.S. Pat. Nos.6,230,814 and 6,591,908. U.S. Pat. No. 6,591,908 also teaches a steamand solvent process wherein the ratio of the two components is variedover time. However, both steam and solvent are injected at all timesduring the process. A further type of a SAP method is taught in U.S.Pat. No. 4,513,819, which involves cyclical steam/solvent injection andproduction steps.

Gates et al., in U.S. Pat. No. 7,464,756, proposes a further variationin a bitumen recovery process. Referred to as the solvent-assistedvapour extraction with steam (SAVES) process, the proposed methodinvolves a sequence of solvent/steam injections to recover bitumen. TheSAVES method comprises three phases. In the first phase, steam and aheavy solvent (C5+) are injected into a formation. In the second phase,the steam and heavy solvent flow rates are gradually reduced while alight solvent (C1-C4) is introduced with a gradually increasing flowrate. In the third phase, injection of the steam and heavy solvent isstopped and the injection of the light solvent continues at a higherrate. After the third phase, a “blow down” procedures is used to recoverthe injected solvents.

Zhao et al. (J. Can. Pet. Tech., 2005, 44(9), pp. 37-43) teach ahydrocarbon production method involving alternating steam and solventinjection, referred to as the steam alternating solvent (SAS) process.In this method, steam and solvent are injected in an alternating mannerwithout any co-injection of the two.

Further examples of bitumen recovery processes known in the art areprovided in U.S. Pat. Nos. 4,519,454; 6,662,872; and 6,708,759, and USApplication publication no. 2008/0017372.

The recovery of bitumen from reservoirs such as oil sands continues tobe of interest particularly in view of the world's increasing energydemand. As such, the need to improve extraction efficiency ofhydrocarbon containing reservoirs continues to gain importance. Despitethe various prior art attempts discussed above, there exists a need foran efficient and cost-effective method for in situ recovery of bitumen.

SUMMARY OF THE INVENTION

In one aspect, the invention provides an improved SAGD method forextracting hydrocarbons from a reservoir containing hydrocarbons,wherein the method comprises the cyclic injection of steam and heavy andlight solvents.

Thus, in one aspect, the invention provides a method of producinghydrocarbons from a subterranean reservoir containing the hydrocarbons,the reservoir including at least one generally horizontal injection welland at least one generally horizontal production well, the productionwell being located vertically below the injection well and proximalthereto, the method comprising:

a) injecting steam and a heavy solvent into the reservoir through the atleast one injection well, the heavy solvent comprising a hydrocarbonhaving a carbon chain length of C4 or greater;

b) reducing the steam injection rate, stopping the heavy solventinjection, and injecting a light solvent, the light solvent comprising ahydrocarbon having a carbon chain length less than the heavy solvent;

c) increasing the steam injection rate to above the rate of step (b),restarting the heavy solvent injection, and continuing the light solventinjection;

d) increasing the steam injection rate to above the rate of step (c),stopping the heavy and light solvent injection; and,

e) reducing the steam injection rate and restarting the light solventinjection.

BRIEF DESCRIPTION OF THE DRAWINGS

Exemplary embodiments of the invention will now be described by way ofexample only with reference to the accompanying drawings, in which:

FIG. 1 is a graph illustrating the correlation between CanadianAthabasca heavy oil/bitumen viscosity and the temperature of thedeposit.

FIG. 2 is a graph illustrating the correlation between Athabasca bitumenviscosity and the volume of solvent added to the deposit.

FIG. 3 illustrates the injection profiles of the steam and solventcomponents used in the present invention.

FIGS. 4 to 6 illustrate a comparison of performance efficiencies of themethod of the invention and a typical SAGD method.

DETAILED DESCRIPTION OF THE INVENTION

For clarity of understanding, the following terms used in the presentdescription will have the definitions as stated below.

As used herein, the terms “reservoir”, “formation”, “deposit”, aresynonymous and refer to generally subterranean reservoirs containinghydrocarbons. As discussed further below, such hydrocarbons may comprisebitumen and bitumen like materials.

“Oil sands”, as used herein, refers to deposits containing heavyhydrocarbon components such as bitumen or “heavy oil”, wherein suchhydrocarbons are intermixed with sand. Although the invention isdescribed herein as being applicable to oil sands, it will be understoodby persons skilled in the art that the invention may also be applicableto other types reservoirs containing bitumen or heavy oil, or other suchhydrocarbon materials (i.e. heavy crude oil). However, for convenience,the terms “oil sands” and “bitumen” are used for the purposes of thefollowing description and will be understood to refer generally to anyof the above mentioned hydrocarbon reservoirs and materials. The choiceof such terms serves to facilitate the description of the invention andis not intended to limit the invention in any way.

The term “solvent” refers to one or more hydrocarbon solvents used inhydrocarbon recovery methods as known in the art. In a preferredembodiment, the solvents of the invention are hydrocarbons comprisingchain lengths of C2 to C10. Examples of suitable solvents for bitumenextraction processes are known in the art, and can include alkanes,naphtha, CO₂ and combinations thereof. The solvent may comprise amixture of one or more hydrocarbon components. As used herein, the terms“light solvent” or “light hydrocarbon” will be understood as comprisingone or more alkane components preferably having a length of C2 to C4,and more preferably C3 (i.e. propane). Similarly, the terms “heavysolvent” or “heavy hydrocarbon” as used herein will be understood ascomprising one or more alkane components preferably having a length ofat least C4, and more preferably at least C5 (i.e. pentane). It willalso be understood that the heavy and light solvents can comprisemixtures of solvents having a desired average chain length. For examplethe heavy solvent may comprise a mixture of hydrocarbons, eachpreferably having a length greater than C4 and wherein the mixture hasan average chain length of approximately C5. In a further preferredaspect, at least ⅓ v/v of the heavy solvent mixture is comprised ofpentane (C5) and/or hexane (C6). Similarly, the light solvent maycomprise a mixture of hydrocarbons, each preferably having a length lessthan C4 and wherein the mixture has an average chain length ofapproximately C3. In a further preferred aspect, at least ½ v/v of thelight solvent mixture is comprised of propane (C3). In a furtherpreferred aspect, the light solvent contains less than about 25 mole %of methane (C1) and ethane (C2). As known in the art, the choice ofsolvents depends on the reservoir or anticipated operating pressure. Theheavy solvent should condense at a temperature that is less than thatfor steam but higher than the average of steam temperature and initialreservoir temperature. Similarly the light solvent, at operatingpressure, should condense at a temperature which is less than theaverage between steam and initial temperatures. The choice of anappropriate solvent for use in the invention will, therefore, beapparent to persons skilled in the art in view of the teaching providedherein.

The term “natural gas liquids” or “NGL” will be understood as comprisingalkane hydrocarbons generally having lengths of C2 to C6, and which arenormally condensation products in the course of natural gas processing.

As discussed above, various methods have been proposed for extracting,or producing, bitumen from oil sands. These generally include gravitydriven heating methods, such as SAGD, and dilution methods, such asVAPEX. FIG. 1 illustrates the effect of heat on bitumen viscosity. Thecurves for varying oil density, or API gravity, show a maximum slope atthe lower temperatures, indicating that small initial in-situ formationtemperature increases produce the largest reductions in oil viscosityper degree of temperature rise. FIG. 2 illustrates the effect of solventinjection on bitumen viscosity. The graph shows the correlation of themole fraction of solvent 14, the solvent in this example being hexane,with the bitumen viscosity 11. The top dotted curve 4 for solvent at 10°C. demonstrates that as the mole fraction of hexane 12 in ahexane/bitumen solution increases, the viscosity 11 of the mixture canbe reduced from millions of centipoises a viscosity of less than 10centipoise. However, in comparison with described SAGD processes, pureunheated solvent applications have proven much more difficult to executein practice, with at least two uneconomic field trials attempted.

The present invention provides an improved method for recoveringhydrocarbons and, more particularly, viscous hydrocarbons fromsubterranean deposits. In a preferred application, the inventionprovides a method for recovering bitumen from oil sands and the like,which incorporates a combination of SAGD and solvent techniques. Ingeneral, the invention requires at least one injection well and at leastone production well. Both the injection and production wells areprovided in a reservoir containing hydrocarbons to be produced (orextracted). The wells are arranged generally horizontally as in atypical SAGD process, wherein the injection wells are positionedvertically above the production wells. As discussed further below, steamand/or one or more solvents are injected into the reservoir, whichresults in mobilization of the bitumen material within the reservoir.The mobilization of bitumen is caused by a reduction in its viscositydue to the heating effect of the injected steam and/or the dilutingeffect of the injected solvent. In either case, the mobilized bitumen isallowed to travel downward due to gravity and is collected in the lowerproduction well. The bitumen entering the production well is thentransported, using pumps and other associated equipment known in theart, to the surface for subsequent processing.

According to the method of the invention, the injection and productionwells are first positioned in the same manner as with known SAGDprocesses. The arrangement and positioning of the wells is known in theart and described, for example in Canadian patent number 1,304,287.However, as discussed below, in one aspect of the invention, the wellspacing may be reduced by half as compared with typical SAGD processesdue to the efficiency of the present method. It will be understood thatthis is an advantage of the invention and not a restriction.Alternatively, the method can be applied to a field already prepared fora SAGD process without altering the well positioning. Once the wells arepositioned and the initial start-up of the SAGD process has beeneffected, the method of the invention can then be commenced. The methodcan be divided into six main phases or stages, I to VI, each takingplace sequentially over a period of time. The switching of one phase toanother is preferably based on a recovery factor, quantified as thepercentage of oil in place (OIP) that has been recovered. These phasesare discussed further below.

Phase I

The first phase of the method begins with the co-injection of steam anda heavy (preferably C5 or greater) solvent into the reservoir. The steaminjection rate is preferably the same as that normally associated withSAGD processes. As known in the art, the steam injection rate will varyaccording to various physical characteristics of the reservoir and othersuch criteria. The present invention is not limited to any particularrate of steam injection. The steam flow rate for Phase I will bereferred to herein as the maximum steam flow rate, SFmax, and will beunderstood to mean a mass flow rate. It will be chosen or determined soas to result in or maintain the desired or necessary pressure in thereservoir. Similarly, all flow rates of solvents will also be understoodto mean mass flow rates.

The preferred, but not exclusive, solvent for Phase I is pentane (C5) ora heavier hydrocarbon, or some combination thereof. The flow rate of theheavy solvent is about 0-20%, and preferably about 4-20%, and morepreferably 8-20% of SFmax. Preferably, no other solvent is injectedduring this phase. As indicated in the range of heavy solvent flow rate,it will be understood that the use of such heavy solvent (e.g. pentaneor another “heavy” hydrocarbon as defined herein) may be omitted in somesituations. One factor for considering the use of the heavy solvent inPhase I is the relative value of such solvent as compared to the bitumenproduct. For example, it may be found that the cost of using the heavysolvent is outweighed by the economic benefit of the recovered bitumen.A further factor that determines the amount of heavy solvent used inPhase I is the rate of recovery of the heavy solvent. Such recovery willbe controlled, inter alia, by the geological properties of the deposit.

In the preferred embodiment, the steam and heavy solvent co-injection ofPhase I is continued until about 25-30% of the OIP has been recovered.

Phase II

In the second phase, steam injection is continued but at a much reducedlevel as compared to Phase I. Preferably, the steam injection rate isreduced to about 8-20%, and preferably 15-20%, of SFmax. The injectionof heavy solvent is stopped and the injection of a light solvent (i.e.C2 to C4) is commenced. In one preferred aspect of the invention, thelight solvent is propane (C3). In another preferred aspect, the flowrate of the light solvent is about 4-8% of SFmax.

Phase II is preferably continued until about 40-45% of the OIP isrecovered.

Phase III

In Phase III, the steam flow rate is increased slightly to about 20-25%of SFmax and both light and heavy solvents are injected. The flow rateof the heavy solvent is about 0-10%, and preferably about 2-10%, ofSFmax and the flow rate of the light solvent is preferably about 3-6% ofSFmax. As noted, the flow rate of the light solvent is preferablyslightly reduced as compared to Phase II. Phase III may therefore becharacterized as a spike in the heavy solvent injection rate. As withPhase I, the amount of the heavy solvent (e.g. pentane) will depend oncertain cost and recovery factors. Thus, in some cases, it may be foundmore economically efficient to avoid using any heavy solvent in PhaseIII.

Phase III is preferably continued until about 56-66%, and preferably58-64%, of the OIP is recovered.

Phase IV

In Phase IV, the steam flow rate is increased slightly from that ofPhase III to about 30-35% of SFmax. The injection of both heavy andlight solvents is stopped. Thus, for Phase IV, only steam is injectedinto the reservoir and, as such, this phase may be characterized as aspike in the steam injection rate.

Phase IV is preferably continued until about 66-72% of the OIP isrecovered.

Phase V

In Phase V, steam injection is reduced to about 15-20% of SFmax. Noinjection of heavy solvent is made; however, light solvent injection isrecommenced at a flow rate of about 2-5% of SF max. This phase maytherefore be characterized as a spike in light solvent injection.

Phase V is preferably continued until about 75-80% of the OIP isrecovered.

Phase VI

Phase VI comprises a blow out phase wherein residual solvent isrecovered, or scavenged, along with a portion of the bitumen in thereservoir. During this phase, no steam or the above mentioned solventsare injected into the reservoir. The solvent recovery is effected byvarious methods known in the art such as injection of methane and/or bydepressurizing the reservoir. For example, the preferred method ofscavenging residual solvent is to inject a non-condensible gas such asmethane, nitrogen, or CO₂ into one or both of the injection andproduction wells of wells arranged in alternating pairs, and to producethe same volume from intervening pairs of wells. It will be understoodthat the invention is not limited to any particular method of solventrecovery. It will also be understood that Phase VI may be eliminated incases where solvent recovery or further bitumen production is noteconomically viable or sustainable.

The final phase may be continued for any required amount of time until,for example, about 85% of the OIP is recovered. However, the duration ofthis phase would be primarily based on the need to scavenge residualsolvent and other economic considerations. For example, if theefficiency of production drops below a certain threshold, Phase VI canbe terminated.

Table 1 below summarizes an example of the above described phases.

TABLE 1 Heavy Light Steam flow solvent solvent rate (pentane) (propane)Example % Maximum flow rate flow rate elapsed Ends @ Steam Rate mass %of mass % of time, Phase % OIP (SFmax) SFmax SFmax years I 25-30 1000-20 0 1 (pref. 4-20) II 40-45  8-20 0 4-8 2 (pref. 15-20) III 56-6620-25 0-10 3-6 3 (pref. 58-64) (pref. 2-10) IV 66-72 30-35 0 0 4 V 75-8015-20 0 2-5 5 VI ~85 0 0 0 10

Although the above table provides examples of the lengths of time foreach phase, the duration of each phase would vary based on variousfactors such as the physical characteristics of the reservoir and thebitumen contained therein, the extraction efficiencies of the equipment,and the number and spacing of the wells. In practice, each phase may beconducted up till a desired recovery threshold of the Oil in Place (OIP)is reached. However, in typical cases, the time period of each stage maybe measured by years.

Various numerical simulations of the method of the invention wereconducted. FIG. 3 illustrates the flow rates of the respective steam,heavy solvent and light solvent injection streams used in one of thetests as each of the above phases was carried out. As can be seen, theflow rate conditions and timing of the phases were similar to thatdescribed above in Table 1.

FIG. 4 illustrates a comparison between extraction of a reservoir usinga typical SAGD process and a process according to the present invention,namely a solvent cycle SAGD (or SC-SAGD). As can be seen, the presentinvention provides a 30% improvement in bitumen extraction efficiency.

FIGS. 5 and 6 illustrate the performance efficiency of the presentinvention (SC-SAGD) as compared to typical SAGD methods. As shown, themethod of the present invention provides a higher oil recovery whilerequiring a much reduced steam to oil ratio (SOR).

As indicated above, the “heavy” and “light” solvents used in the presentmethod may be either single types of hydrocarbons or may comprise amixture of hydrocarbons. In the typical scenario, the solvents willcomprise such a mixture and, preferably, with a greater proportion beingmade up of a desired weight of solvent. For example, although pentane isindicated above as a “heavy” solvent, a natural gas condensate, ornatural gas liquid (NGL) may be used, consisting of preferably more than⅓ (v/v) of pentanes plus hexanes. The liquid volume of the NGL used forthis purpose would be the same as indicated above with respect topentane by itself. Alternatively, butane may be substituted for pentaneas the heavy solvent. In addition, unlike other solvent based extractionmethods, the purity of the solvent is not critical for the method of theinvention; however, when recycling propane, the presence of methane orother light gases should preferably be limited to less than about 25%mole fraction. As such, the operating costs associated with solventrefining are mitigated by the present invention.

As will be understood, the method of the invention provides an improvedand more efficient process for recovering bitumen than a SAGD processalone. Although the invention is adapted to be used for an existing SAGDwell arrangement, in new fields, the spacing of wells for the purpose ofthe invention can be reduced by 50%, thereby reducing the facility andoperating costs associated with the recovery process. In particular, byallowing a reduced well spacing, the invention reduces by as much as 50%the amount of heat consumption normally associated with SAGD methods.Further, the solvent scavenging process can also be brought forward intime, which will reduce the cost associated with the solvent inventoryduring recovery.

By combining solvent injection with steam, the invention is able torealize a major reduction in the steam to oil ratio (SOR) and cumulativesteam to oil ratio (CSOR) as compared a SAGD process alone.

Although the invention has been described with reference to certainspecific embodiments, various modifications thereof will be apparent tothose skilled in the art without departing from the purpose and scope ofthe invention as outlined in the claims appended hereto. The drawingsprovided herein are solely for the purpose of illustrating variousaspects of the invention and are not intended to be drawn to scale or tolimit the invention in any way. The disclosures of all prior art recitedherein are incorporated herein by reference in their entirety.

1. A method of producing hydrocarbons from a subterranean reservoircontaining said hydrocarbons, the reservoir including at least onegenerally horizontal injection well and at least one generallyhorizontal production well, the production well being located verticallybelow the injection well and proximal thereto, the method comprising: a)injecting steam and, optionally, a heavy solvent into the reservoirthrough the at least one injection well, the heavy solvent comprisingone or more hydrocarbons having a carbon chain length of C4 or greater;b) reducing the steam injection rate, stopping the heavy solventinjection, and injecting a light solvent, the light solvent comprisingone or more hydrocarbons having a carbon chain length less than theheavy solvent; c) increasing the steam injection rate to above the rateof step (b), optionally restarting the heavy solvent injection, andcontinuing the light solvent injection; d) increasing the steaminjection rate to above the rate of step (c), stopping the heavy andlight solvent injection; and, e) reducing the steam injection rate andrestarting the light solvent injection.
 2. The method of claim 1,further comprising a further step of: f) stopping injection of the steamand light solvent and scavenging residual solvents from the reservoir.3. The method of claim 1, wherein the heavy solvent is pentane or ahydrocarbon mixture having an average chain length of about C5 orgreater and comprising at least ⅓ by volume of pentane and/or hexane. 4.The method of claim 1, wherein the light solvent is propane or ahydrocarbon mixture having an average chain length of about C3 andcomprising at least ½ by volume of propane.
 5. The method of claim 4,wherein the light solvent contains less than about 25 mole % of methaneand ethane.
 6. The method of claim 1, wherein step (a) is continueduntil about 25-30% of the oil in place has been recovered.
 7. The methodof claim 1, wherein step (b) is continued until about 40-45% of the oilin place has been recovered.
 8. The method of claim 1, wherein step (c)is continued until about 56-66%, or about 58-64%, of the oil in placehas been recovered.
 9. The method of claim 1, wherein step (d) iscontinued until about 66-72% of the oil in place has been recovered. 10.The method of claim 1, wherein step (e) is continued until about 75-80%of the oil in place has been recovered.
 11. The method of claim 2,wherein step (f) is continued until about 85% or more of the oil inplace has been recovered.
 12. The method of claim 1, wherein, in step(a), the flow rate of the heavy solvent is 0-20% of the flow rate of thesteam.
 13. The method of claim 1, wherein, in step (a), the flow rate ofthe heavy solvent is 4-20% of the flow rate of the steam.
 14. The methodof claim 1, wherein, in step (b), the flow rate of the steam is 8-20% ofthe steam flow rate of step (a) and wherein the flow rate of the lightsolvent is 4-8% of the steam flow rate of step (a).
 15. The method ofclaim 1, wherein, in step (c): the flow rate of the steam is 20-25% ofthe steam flow rate of step (a); the flow rate of the heavy solvent is0-10% of the steam flow rate of step (a); and the flow rate of the lightsolvent is 3-6% of the steam flow rate of step (a).
 16. The method ofclaim 1, wherein, in step (d), the flow rate of the steam is 30-35% ofthe steam flow rate of step (a).
 17. The method of claim 1, wherein, instep (e), the flow rate of the steam is 15-20% of the steam flow rate ofstep (a) and wherein the flow rate of the light solvent is 2-5% of thesteam flow rate of step (a).